Coating and/or treating hydraulic fracturing proppants to improve wettability, proppant lubrication, and/or to reduce damage by fracturing fluids and reservoir fluids

ABSTRACT

Surface modified oil and gas well hydraulic fracturing proppants for improving wettability, altering chemical reactivity, altering surface topography, imparting lubricity or controlling relative permeability to flow of fluids of such proppants. The use and preparation of such coated proppants in hydraulic fracturing of subterranean formations is also described.

CROSS-REFERENCE TO RELATED APPLICATIONS

This patent application is a non-provisional of U.S. Patent ApplicationNo. 60/561,486, filed on Apr. 12, 2004, entitled “Coating and/orTreating Hydraulic Fracturing Proppants to Improve Wettability, ProppantLubrication, and/or to Reduce Damage by Fracturing Fluids and ReservoirFluids,” which is incorporated by reference herein in its entirety.

BACKGROUND OF THE INVENTION

The present invention relates to oil and gas well proppants and, moreparticularly, to processes for physically or chemically modifying thesurface characteristics of hydraulic fracturing proppants.

Oil and natural gas are produced from wells having porous and permeablesubterranean formations. The porosity of the formation permits theformation to store oil and gas, and the permeability of the formationpermits the oil or gas fluid to move through the formation. Permeabilityof the formation is essential to permit oil and gas to flow to alocation where it can be pumped from the well. Sometimes thepermeability of the formation holding the gas or oil is insufficient foroptimal recovery of oil and gas. In other cases, during operation of thewell, the permeability of the formation drops to the extent that furtherrecovery becomes uneconomical. In such cases, it is necessary tofracture the formation and prop the fracture in an open condition bymeans of a proppant material or propping agent. Such fracturing isusually accomplished by hydraulic pressure, and the proppant material orpropping agent is a particulate material, such as sand, glass beads orceramic particles, which are carried into the fracture by means of afluid.

Spherical particles of uniform size are generally acknowledged to be themost effective proppants due to maximized permeability. For this reason,assuming other properties to be equal, spherical or essentiallyspherical proppants, such as rounded sand grains, metallic shot, glassbeads and tabular alumina, are preferred.

Conductivity is a measure of how easily fluids can flow through proppantor sand and generally the higher the conductivity, the better. Currentindustry practices with existing proppants typically result in 50% orgreater conductivity loss due to damage by fracturing fluids that arerequired to transport the proppant into the fracture.

It is known in the art to resin-coat proppants and to treat fracturesand formations to reduce buildup of barium sulfate scale in the fractureand wellbore.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

The present process is one for modifying the surface properties ofhydraulic fracturing proppants. Proppants are natural sands or ceramicgranules used in the hydraulic fracturing of oil and gas wells. Forinstance, see U.S. Pat. Nos. 4,068,718, 4,427,068, 4,440,866 and5,188,175, the entire disclosures of which are incorporated herein byreference. When pumped into well fractures at high pressure, theproppants “prop” open the fractures and create conduits through whichoil and gas easily flow, thereby increasing well production.

Embodiments of the present invention relate to modifying the surfaceproperties of natural sand, resin-coated sand and manufactured proppantsused in oil and gas recovery to achieve one or more of the followingdesirable effects: alter the wettability, alter the chemical reactivity,alter the surface topography, impart lubricity, and control relativepermeability to flow of fluids of such proppants. Sands, resin coatedsands or manufactured proppants are treated, such as by coating, so asto provide a smoother surface to the particles/proppants, to modifytheir wettability or fluid affinity, to modify their chemicalreactivity, or to reduce particle-to-particle friction properties.

These benefits can be achieved by a variety of techniques, includingcoating the proppants with a hydrophobic material such as siliconcontaining compounds, including silicone materials and siloxanes,polytetrafluoroethylene (commonly known as Teflon®), plant oils, such aslinseed oil, soybean oil, corn oil, cottonseed oil, vegetable oil(widely commercially available such as Crisco®), and canola oil, andhydrocarbons such as kerosene, diesel, and crude oil, petroleumdistillates such as hydrocarbon liquids comprising a mixture of C₇-C₁₂aliphatic and alicyclic hydrocarbons and aromatic hydrocarbons (C₇-C₁₂),commonly known as Stoddard Solvent, aliphatic solvents, solvent naphtha(medium aliphatic and light aromatic), and paraffin, such as solventdewaxed heavy paraffinic petroleum distillate. According to the presentinvention, the coating is applied to the proppant by one or more of avariety of techniques well known to those of ordinary skill in the artincluding chemically coating the proppant by means of spraying, dippingor soaking the proppant in a liquid solution of the hydrophobicmaterial, application of a sheet of film such as copolymerizedpolyvinylidene chloride (commercially available as Saran Wrap®) toessentially “shrink-wrap” the proppant and encapsulate it in achemically desirable coating, fusing material to the proppant in amanner similar to that utilized to fuse toner in a laser printer byplacing heated proppant into a fusible powder such as a glass frit orenamel which will bond to the proppant pellet, electroplating usingelectrostatic techniques well known to those of ordinary skill in theart to transfer a coating material such as a less chemically reactivemetallic layer to the proppant, plasma spraying, sputtering, fluidizingthe proppant in a fluidized bed such as according to techniquesdescribed in U.S. Pat. No. 4,440,866, the entire disclosure of which isincorporated herein by reference, and powder coating. Those of ordinaryskill in the art will recognize that other techniques may also be usedto suitably apply a substantially uniform consistent coating to theproppant. Those of ordinary skill in the art will also recognize thatthe proppant may be coated with a solid coating, such as glass frit,high alumina clays or bauxites, metals, or other hydrophobic powders.Such coatings could be applied by spraying, tumbling, or other meansknown in the art for applying powder coatings.

One such coating according to the present invention may be generallydescribed as a silicon containing compound. In certain embodiments ofthe present invention, the silicon containing compound is a siloxanebased on the structural unit R₂SiO, wherein R is an alkyl group. Inother certain embodiments of the present invention, the siliconcontaining compound is a nonvolatile linear siloxane of the composition:

where (R₁) is an alkyl group having from one to three carbon atoms, (R₂)is either a hydrogen atom or an alkyl group having from one to threecarbon atoms, (R₃) is an alkyl group having from one to four carbonatoms and n is a number between 50 and 200. In still other certainembodiments of the present invention, the suitable silicon containingcompounds include polymethylhydrogen siloxane and polydimethyl siloxane.

In one process of the present invention, natural sands, manufacturedproppants, and resin-coated materials are treated with a chemicaltreatment to reduce conductivity loss caused by fracturing fluids, toalter or modify proppant wettability, to control the relativepermeability to flow of fluids which may be encountered in thereservoir, to “lubricate” the proppant to allow more efficient proppantarrangement when the fracture closes, and to reduce eventual scalebuildup on proppant. According to one process of the present inventionnatural sands, manufactured proppants, and resin-coated materials aretreated to reduce conductivity loss caused by fracturing fluids bysaturating such proppant materials with hydrophobic materials asdescribed above. According to another process of the present inventionnatural sands, manufactured proppants, and resin-coated materials aretreated to alter or modify proppant wettability and consequently improvemultiphase flow by coating the proppant materials with the siliconematerials described above. Thus, various embodiments of the presentinvention relate to concepts and techniques to treat fracturing sandand/or proppant to:

-   -   1) reduce conductivity loss due to fracturing fluids,    -   2) alter or modify proppant wettability, to control the relative        permeability to flow of the fluids which may be encountered in        the reservoir (such as oil, water, gas, chemical treatments, and        fracturing fluids),    -   3) “lubricate” the proppant to allow more efficient proppant        arrangement when the fracture closes, effectively increasing        packing efficiency and reducing the extent of proppant crushing,    -   4) reduce eventual scale buildup on proppant, and    -   5) reduce the chemical reactivity of proppant to materials        encountered in the reservoir or well treatment, including but        not limited to: oil, gas, water, brine, fracturing fluids,        remedial acid treatments, caustic fluids commonly associated        with steam or water injection, biological agents or their        byproducts such as carbon dioxide and hydrogen sulfide.

Any one or more of these benefits may be achieved in a variety of ways,including but not limited to reducing chemical reactivity of theproppant by “treating” the proppant. In certain examples, treating theproppant comprises applying an inert coating, applying a coating whichresults in a physically smoother surface thereby reducing surface areaexposed to reaction with fluids, modifying the wettability and fluidaffinity of the proppant, and modifying proppant surface to reducegrain-to-grain friction. Thus, exemplary techniques for treatingfracturing sand and/or proppant include but are not limited to:

-   -   1) reducing chemical reactivity of proppant by applying an inert        coating,    -   2) applying a coating which results in a physically smoother        surface thereby reducing surface area exposed to reaction with        the fluids,    -   3) modifying the wettability and fluid affinity of the proppant,        and    -   4) modifying proppant surface to reduce grain-to-grain friction.

Exemplary techniques for treating proppant with chemical coatingsinclude: treating the proppant prior to the fracturing treatment;treating the proppant “on the fly” during the fracturing treatment; or,applying post-fracturing “squeeze” treatments in which an existingfracture and/or formation is contacted with chemicals. Thus, exemplarytechniques for treating proppant include but are not limited to:

-   -   1) pretreating proppant prior to the fracturing treatment,    -   2) treating proppant “on the fly” during the fracturing        treatment, and    -   3) post-fracturing “squeeze” treatments in which an existing        fracture and/or formation can be contacted with chemicals to        produce the above-mentioned benefits.

The techniques for treating proppant are not limited to proppant type,and are applicable to natural sands, manufactured proppants, andresin-coated materials. In addition, a variety of chemicals, or“coatings”, produce the desired effects.

According to various embodiments of the present invention, resin-coatedproppants achieve increases in proppant pack strength by reducingpoint-loading by addition of a structural resin. The “lubrication”concept reduces proppant friction, allowing superior proppantredistribution during fracture closing. This redistribution allows moreefficient packing of proppant, thereby increasing grain-to-grain contactand effectively increasing proppant pack strength and reducing proppantcrush.

According to embodiments of the present invention, coatings affectwettability and provide significant flow benefits under multiphase flowas evidenced by the trapped gas saturation, the altered surfacetension/contact angles, and the electrostatic charges on the coatedproppant. In water drainage studies, it was noted that the coatedproppant would remain dry and hold an 8 to 10 inch column of water abovethe pack until the hydrostatic head exceeded the capillary pressure ofthe highly altered wettability proppant. It is clear that thisalteration of surface wettability has a large impact on the relativepermeability under multiphase flow conditions.

Products with an “oil-wet” surface may be ideal in a gas well producingwater, while products with a different wettability may give preferentialflow to oil and reduce watercut. A variety of different coatings may berequired to minimize gel damage, and may be customized to the specificgel chemistry. Additional coatings may be applied to lubricateproppants, or resist the deposition of scale, asphaltenes, or othermechanical plugging.

In formations frequently treated with acid as a remedial operation,proppant may be coated to minimize reactivity. Traditional untreatedproppants are known to be damaged due to exposure to acid. In additionto damaging the proppant, this reactivity also consumes acid andprevents it from attacking the targeted formation fines or othermaterial which has plugged the proppant pack. Thus, coatings may also beapplied over resin-coated proppants so as to minimize the chemicalinteraction of such proppants with fracturing fluids.

Traditional untreated proppants are also known to be highly damaged bycaustic fluids associated with high temperature water and/or steaminjection. The modified proppants of the present invention will havereduced chemical reactivity and will improve performance and longevityin oil fields with steam injection.

Contrary to traditional scale inhibition treatments which focus onimpregnating the reservoir and/or proppant with chemicals which arereleased over time and react with scale forming constituents to reduceor eliminate the amount of scale which will form in the formation,fracture, and/or wellbore tubulars, the embodiments of the presentinvention involve chemically or otherwise altering the surface of theproppant to reduce the tendency of scale to attach to the proppant. Thisproppant coating does not chemically react with the produced fluids toprohibit scale formation, but instead reduces chemical reactions betweenthe proppant and surrounding fluids. These fluids may include, but arenot limited to, oil, gas, water, brine, fracturing fluids, remedial acidtreatments, caustic steam or water and biological agents.

Illustrative treated proppants, methods for their preparation andmethods for their use will now be discussed with respect to thefollowing Examples 1-7.

EXAMPLE 1

Coated samples of a sintered bauxite proppant commercially availablefrom CARBO Ceramics, Inc. under the tradename CARBOHSP™, a sand proppantcommercially available from Badger Mining Co. under the tradename BadgerSand, and a resin-coated sand proppant commercially available fromBorden Chemical Inc. under the tradename SB Prime were prepared bycoating the proppant with the materials set forth in Table 1 below. Eachof the samples of CARBOHSP™, Badger Sand and SB Prime had a particlesize distribution that met the API designation for 20/40 proppant whichspecifies that the product must retain 90% between the primary 20 and 40mesh sieves. This particle size distribution will be referred to hereinas “20/40 U.S. Mesh.”

In each case, the coating was applied by mixing the proppant and thecoating in a beaker for approximately 30 minutes, then drying it forapproximately 15 to 18 hours in an oven. Other methods for applying acoating include, but are not limited to, other “submerging” processessimilar to the process as described in this example, spraying, andmixing in mixers and mullers such as those available from EirichMachines, Inc. Still other methods well known to those of ordinary skillin the art are also suitable for applying a coating to the proppantmaterials as described herein.

The coating materials were added as follows. Polymethylhydrogen siloxanewas added as either a 2 or 5 weight percent emulsion of siloxane inwater, polydimethyl siloxane was added as a 5 weight percent emulsion ofsiloxane in water and Stoddard Solvent was added without dilution. Allsamples were dried at 113° C. for approximately 15 to 18 hours.

The water retention data set forth in Table 1 for the CARBOHSP sampleswas determined by pouring 10 g. of water through a standard column ofproppant (6g., about 8 cm. height) and determining the percentage ofwater that was retained in the column. The water retention data for theBadger Sand and the SB Prime resin-coated sand was determined by pouring50 ml of water through a 10 g. column of the sand and determining thepercentage of water that was retained in the column. The water retentiondata set forth in Table 1 is an average of three tests per coating. Thesiloxane materials showed at least a two-fold reduction in waterretention compared to the uncoated proppant, whether the proppant beCARBOHSP, sand or resin-coated sand. Meanwhile, Stoddard Solvent showedsome reduction, but was not as effective as the siloxanes. Also, theresults for the 2% polymethyl hydrogen siloxane, applied to proppant at75° C. demonstrates that an effective coating can be achieved while theproppant is still warm. Thus, an effective coating can be applied rightafter the cooler in production. Table 1 below sets forth results of thetesting of such samples. TABLE 1 Bulk 15k Water Density Crush RetentionProppant Coating (g/cm³) ASG (%) (%) CARBOHSP uncoated 2.03 3.54 3.413.7 CARBOHSP Stoddard Solvent 2.01 3.48 2.7 12.3 CARBOHSP 5%polydimethyl 2.02 3.33 1.3 5.1 siloxane CARBOHSP 5% poly methyl 1.943.09 1.7 6.0 hydrogen siloxane CARBOHSP 2% poly methyl 1.99 3.30 2.4 3.7hydrogen siloxane CARBOHSP 2% poly methyl 2.01 3.11 3.0 4.4 hydrogensiloxane, applied when proppant was 75° C. Badger Sand uncoated 1.552.63 51.0 5.2 Badger Sand 2% poly methyl 1.55  1.91* 47.2 2.4 hydrogensiloxane SB Prime uncoated 1.48 2.55 18.6 5.8 resin-coated sand SB Prime2% poly methyl 1.55 2.18 13.6 1.5 resin-coated hydrogen siloxane sand*Significant number of air bubbles trapped on sample.

The term “bulk density”, as set forth in Table 1, means the weight perunit volume, including in the volume considered the void spaces betweenthe particles.

The term “ASG” as set forth in Table 1, refers to “apparent specificgravity” which is a number without units, but is defined to benumerically equal to the weight in grams per cubic centimeter of volume,excluding void space or open porosity in determining the volume. Theapparent specific gravity values given herein were determined by waterdisplacement.

The crush values reported in Table 1 were obtained using the AmericanPetroleum Institute (API) procedure for determining resistance tocrushing. According to this procedure, a bed of about 6 mm depth ofsample to be tested is placed in a hollow cylindrical cell. A piston isinserted in the cell. Thereafter, a load is applied to the sample viathe piston. One minute is taken to reach maximum load which is then heldfor two minutes. The load is thereafter removed, the sample removed fromthe cell, and screened to separate crushed material. The results arereported as a percentage by weight of the original sample.

The reduction in apparent specific gravity (“ASG”) for each of theproppant samples set forth in Table 1 indicates that the coatings arewaterproofing the proppant surface by preventing water from enteringsome of the surface porosity. Also, the CARBOHSP proppant coated withpolymethylhydrogen siloxane and polydimethyl siloxane exhibited asignificant reduction in crush compared to the uncoated control.

EXAMPLE 2

Coated samples of a sintered bauxite proppant commercially availablefrom CARBO Ceramics Inc. under the tradename CARBOHSP™ (20/40 U.S. Mesh)were prepared by coating the proppant with a product that iscommercially available from SOPUS Products under the tradename“Rain-X®”. Rain-X® is a glass surface treatment material that includespolyalkyl hydrogen siloxane, ethanol and isopropanol. The coating wasapplied by mixing the proppant and the coating in a beaker forapproximately 30 minutes, then removing the coated proppant from thebeaker and drying it for approximately 15 to 18 hours in an oven.

Other coatings that may be applied to proppants include, but are notlimited to, spray Teflon, liquid silicone, Black Magic™ and WD-40®.Black Magic™ is commercially available from SOPUS Products and containspolydimethyl siloxane, also known as “silicone oil” and hydrotreatedlight petroleum distillates. The hydrotreated light petroleumdistillates can be generally described as a mixture of C₁₀-C₁₄naphthenes, iso- and n-paraffins containing <0.1% aromatics and <0.1%hexane. The average molecular weight of the hydrotreated light petroleumdistillates tends to be closer to C14, i.e. about 200. The boiling pointof the hydrotreated light petroleum distillates is from 175-270° C. Thedensity of the hydrotreated light petroleum distillates is from0.79-0.82 g/cm³. WD-40® is commercially available from the WD 40 Companyand is primarily a mixture of Stoddard solvent and heavy paraffinicsolvent-dewaxed petroleum distillates. Stoddard Solvent can be generallydescribed as a mixture of C₇-C₁₂ aliphatic and alicyclic hydrocarbonsand aromatic hydrocarbons (C₇-C₁₂), usually with little or no benzene.The boiling point of Stoddard Solvent is from 130-230° C. The density ofStoddard Solvent is from 0.765-0.795 g/cm³. Heavy paraffinicsolvent-dewaxed petroleum distillates can be generally described asaliphatic C₂₀-C₄₀ hydrocarbons having an average molecular weight ofabout 372, corresponding to about C₂₆₋₂₇. The boiling point of heavyparaffinic solvent-dewaxed petroleum distillates is about 293° C.

Other methods for applying a chemical coating include, but are notlimited to, other “submerging” processes similar to the process asdescribed in this example, spraying, and mixing in mixers and mullerssuch as those available from Eirich Machines, Inc. Still other methodswell known to those of ordinary skill in the art are also suitable forapplying a coating to the proppant materials as described herein.

As will be described further with respect to Example 4, the followingproperties of uncoated and coated (20/40 U.S. Mesh) samples of CARBOHSP™were evaluated: conductivity, permeability and percent (%) retainedpermeability.

EXAMPLE 3

Coated samples of a lightweight proppant commercially available fromCARBO Ceramics Inc. under the tradename CARBOLITE® (20/40 U.S. Mesh)were prepared by coating the proppant with a product that iscommercially available from SOPUS Products under the tradename“Rain-X®”. Rain-X® is a glass surface treatment material that includespolyalkyl hydrogen siloxane, ethanol and isopropanol. The coating wasapplied by mixing the proppant and the coating in a beaker forapproximately 30 minutes, then removing the coated proppant from thebeaker and drying it for approximately 15 to 18 hours in an oven.

Other coatings that may be applied to proppants include, but are notlimited to, spray Teflon, liquid silicone, Black Magic™ which iscommercially available from SOPUS Products and contains hydrotreatedlight petroleum distillates and polydimethyl siloxane which is alsoknown as “silicone oil,” and WD-40® which is commercially available fromthe WD 40 Company and is primarily a mixture of Stoddard solvent andheavy paraffinic solvent-dewaxed petroleum distillates.

Other methods for applying a coating include, but are not limited to,other “submerging” processes similar to the process as described in thisexample, spraying, and mixing in mixers and mullers such as thoseavailable from Eirich Machines, Inc. Still other methods well known tothose of ordinary skill in the art are also suitable for applying acoating to the proppant materials as described herein.

As will be described further with respect to Example 4, the followingproperties of uncoated and coated (20/40 U.S. Mesh) samples ofCARBOLITE® were evaluated: conductivity, permeability and percent (%)retained permeability.

EXAMPLE 4

In order to evaluate the effect of a coated and uncoated proppantsurface on the cleanup potential of a guar and borate fracture fluidsystem, in terms of conductivity, permeability and percent (%) retainedpermeability, slurry samples of uncoated CARBOHSP™, 5% poly methylhydrogen siloxane coated CARBOHSP™ from Example 1, 5% polydimethylsiloxane coated CARBOHSP™ from Example 1, Stoddard Solvent coatedCARBOHSP™ from Example 1, Rain-X® coated CARBOHSP™ of Example 2,uncoated CARBOLITE®, and Rain-X® coated CARBOLITE® of Example 3 wereprepared. Each of the proppant samples evaluated according to thisExample 4 had a particle size distribution of 20/40 U.S. Mesh. Theslurry for each sample comprised the proppant and a fracture fluidcomprised of 40 lb/1000 gal Guar (dry powder) and 1.0 gal/1000 galFracsal (high temperature borate crosslinker-oil base slurry).

Conductivity is a measure of how easily fluids can flow through proppantor sand and generally the higher the conductivity, the better. Fracturefluids may be formulated to cross-link and become more viscous withtime. After proppant is placed within the fracture, the fracture fluidsare designed so that the gels break and are able to be flushed out.Ideally, all of the gelled fracture fluid is washed out, however, inpractice, at least some of the gel sticks to the proppant. Quantitativemeasures of how much of the fracture fluid is flushed out arepermeability and percent retained permeability compared to a controlproppant that has not been exposed to fracture fluid.

The control material used for comparison purposes with respect to theCARBOHSP™ samples in this Example 4 was a 20/40 U.S. Mesh CARBOHSP™sample subjected to 6000 psi closure stress that had never been exposedto a guar and borate fracture fluid system. The control material yieldeda permeability of 410 Darcies. Thus, an ideal CARBOHSP™ proppant afterexposure to the guar and borate fracture fluid system would yield apermeability of 410 Darcies and when compared to the control, a percentretained permeability of 100%.

The control material used for comparison purposes with respect to theCARBOLITE® samples in this Example 4 was a 20/40 U.S. Mesh CARBOLITE®sample subjected to 4000 psi closure stress but that had never beenexposed to a guar and borate fracture fluid system. The control materialyielded a permeability of 450 Darcies. Thus, an ideal CARBOLITE®proppant after exposure to the guar and borate fracture fluid systemwould yield a permeability of 450 Darcies and when compared to thecontrol, a percent retained permeability of 100%.

The term “regain” as set forth below refers to how much permeability isregained by flushing out the fracture fluid.

The fracture fluid was prepared as follows: The polymer (guar) washydrated at a pH near 7.0. Following hydration, the pH was adjusted with10 lb/1000 gal K₂CO₃ to 10.2, and a 0.1 lb/1000 gal AP breaker wasadded. Finally, the 1.0 gal/1000 gal Fracsal (borate crosslinker) wasadded.

The slurry was then prepared by mixing about 64 grams of the selectedproppant with 30 ml of the crosslinked guar/borate fracture fluid.

The slurry was top loaded between two saturated Ohio Sandstone cores tomimic actual conditions in an oil or gas well. Static leakoff, whichconsists of draining off excess fluid at low pressure, was conducted ata closure stress of from 100 psi to 1000 psi and a temperature of from150° F. to 200° F. ramped over 90 minutes. After the static leakoff wascompleted, the test was shut-in for heating and breaking overnight(minimum 12 hrs). After overnight shut-in, flow was initiated throughthe pack at 0.5 ml/min to obtain the pressure drop required to initiateflow which is identified as “<dp” in the Tables of data set forth inthis Example 4. Generally, the lower the pressure drop, the better as itis easier to start the cleanout. Following this, the rate was stepwiseincreased to 2.0 ml/min at the 1000 psi closure stress. After obtainingconductivity and widths, the closure was ramped at 100 psi/min to thetarget evaluation closure stress.

The CARBOHSP™ samples were evaluated at 6000 psi closure stress and 200°F. The CARBOLITE® samples were evaluated at 4000 psi closure stress and200° F. Cleanup was evaluated at 2 ml/min with 2% KCI for 50 hours.During data acquisition, the rate was increased to 4 ml/min to obtain asystem check of data linearity. The rate was returned to 2 ml/min afterdata acquisition.

The results for conductivity and permeability of an uncoated CARBOHSP™sample are reported in Table 2 below: TABLE 2 Hrs at Closure & ClosureTemp Conductivity Permeability Temperature (psi) Deg F. (mD-ft) Width(in) (Darcies) −15 1000 150-200 Leakoff while heating and breaking −1.51000 200 876 0.188 <dp = .0054 56 −1 1000 200 1797 0.186 psi at 116 −0.72000 200 3793 0.184 0.5 ml/min 247 −0.5 4000 200 3744 0.182 247 0 6000200 3166 0.174 218 5 6000 200 3009 0.173 209 10 6000 200 2919 0.171 20520 6000 200 2893 0.171 203 30 6000 200 2865 0.171 201 40 6000 200 28360.171 199 50 6000 200 2824 0.171 198

As reported in Table 2, after 50 hours regain, the uncoated CARBOHSP™yielded a conductivity of 2824 mD-ft and 198 Darcies permeability for apercent retained permeability of 48% pared to the control. The percentretained permeability of the uncoated CARBOHSP sample was used forcomparison purposes to the coated CARBOHSP samples evaluated below.

The results for conductivity and permeability of the 5% poly methylhydrogen siloxane coated CARBOHSP™ from Example 1 are reported in Table3 below: TABLE 3 Hrs at Closure & Closure Temp Conductivity PermeabilityTemperature (psi) Deg F. (mD-ft) Width (in) (Darcies) −15 1000 150-200Leakoff while heating and breaking −1.5 1000 200 1118 0.191 <dp = .005070 −1.4 1000 200 1175 0.191 psi at 74 −1.2 2000 200 4519 0.188 0.5ml/min 288 −0.9 3000 200 4763 0.185 309 −0.6 4000 200 4519 0.183 296−0.3 5000 200 4298 0.181 285 0 6000 200 4111 0.179 276 5 6000 200 40610.178 274 10 6000 200 4007 0.177 272 20 6000 200 3961 0.176 270 30 6000200 3909 0.176 267 40 6000 200 3893 0.176 265 50 6000 200 3850 0.176 263

As reported in Table 3, after 50 hours regain, the polymethyl hydrogensiloxane coated CARBOHSP yielded a conductivity of 3850 mD-ft and 263Darcies permeability for a percent retained permeability of 64% comparedto the control. Thus, the percent retained permeability of thepolymethyl hydrogen siloxane coated CARBOHSP proppant of Example 1 was16% greater than the uncoated CARBOHSP proppant.

The results for conductivity and permeability of the 5% polydimethylsiloxane coated CARBOHSP™ from Example 1 are reported in Table 4 below:TABLE 4 Hrs at Closure & Closure Temp Conductivity PermeabilityTemperature (psi) Deg F. (mD-ft) Width (in) (Darcies) −15 1000 150-200Leakoff while heating and breaking −1.5 1000 200 402 0.191 <dp = .010725 −1.4 1000 200 2917 0.191 psi at 183 −1.2 2000 200 4943 0.190 0.5ml/min 312 −0.9 3000 200 5084 0.188 325 −0.6 4000 200 5234 0.185 340−0.3 5000 200 4809 0.181 319 0 6000 200 4533 0.180 302 5 6000 200 43310.179 290 10 6000 200 4402 0.178 297 20 6000 200 4263 0.178 287 30 6000200 4183 0.177 284 40 6000 200 4142 0.177 281 50 6000 200 4121 0.177 279

As reported in Table 4, after 50 hours regain, the polydimethyl siloxanecoated CARBOHSP yielded a conductivity of 4121 mD-ft and 279 Darciespermeability for a percent retained permeability of 68% compared to thecontrol. Thus, the percent retained permeability of the polydimethylsiloxane coated CARBOHSP proppant of Example 1 was 20% greater than theuncoated CARBOHSP proppant.

The results for conductivity and permeability of the Stoddard Solventcoated CARBOHSP™ from Example 1 are reported in Table 5 below: TABLE 5Hrs at Closure & Closure Temp Conductivity Permeability Temperature(psi) Deg F. (mD-ft) Width (in) (Darcies) −15 1000 150-200 Leakoff whileheating and breaking −1.5 1000 200 147 0.194 <dp = .0304 9 −1.4 1000 2002928 0.194 psi at 181 −1.2 2000 200 4298 0.193 0.5 ml/min 267 −0.9 3000200 4094 0.188 261 −0.6 4000 200 3907 0.186 252 −0.3 5000 200 3582 0.183235 0 6000 200 3247 0.181 215 5 6000 200 3514 0.178 237 10 6000 200 34820.177 236 20 6000 200 3447 0.176 235 30 6000 200 3438 0.176 234 40 6000200 3426 0.176 234 50 6000 200 3418 0.176 233

As reported in Table 5, after 50 hours regain, the Stoddard solventcoated CARBOHSP yielded a conductivity of 3415 mD-ft and 233 Darciespermeability for a percent retained permeability of 57% compared to thecontrol. Thus, the percent retained permeability of the Stoddard solventcoated CARBOHSP proppant of Example 1 was 9% greater than the uncoatedCARBOHSP proppant.

The results for conductivity and permeability of the Rain-X® coatedCARBOHSP™ of Example 2 are reported in Table 6 below: TABLE 6 Hrs atClosure & Closure Temp Conductivity Permeability Temperature (psi) DegF. (mD-ft) Width (in) (Darcies) −15 1000 150-200 Leakoff while heatingand breaking −1.5 1000 200 860 0.188 <dp = .0054 55 −1 1000 200 39470.186 psi at 255 −0.7 2000 200 4402 0.184 0.5 ml/min 287 −0.5 4000 2004235 0.182 279 0 6000 200 3375 0.174 233 5 6000 200 3574 0.173 248 106000 200 3652 0.171 256 20 6000 200 3866 0.171 271 30 6000 200 38980.171 274 40 6000 200 3917 0.171 275 50 6000 200 3902 0.171 274

As reported in Table 6, after 50 hours regain, the Rain-X® coatedCARBOHSP yielded conductivity of 3902 mD-ft and 274 Darcies permeabilityfor a percent retained permability of 67% compared to the control. Thus,the percent retained permeability of the Rain-X® coated CARBOHSPproppant of Example 2 was 19% greater than the uncoated CARBOHSPproppant.

The results for conductivity and permeability of the uncoated CARBOLITE®are reported in Table 7 below: TABLE 7 Hrs at Closure & Closure TempConductivity Permeability Temperature (psi) Deg F. (mD-ft) Width (in)(Darcies) −15 1000 150-200 Leakoff while heating and breaking −1 1000200 1585 0.230 <dp = .0032 83 −0.7 1000 200 3707 0.230 psi at 193 −0.52000 200 5512 0.227 0.5 ml/min 291 0 4000 200 4050 0.222 219 5 4000 2004249 0.221 231 10 4000 200 4201 0.220 229 20 4000 200 4160 0.220 227 304000 200 4138 0.220 226 40 4000 200 4120 0.220 225 50 4000 200 41120.220 224

As reported in Table 7, after 50 hours regain, the uncoated CARBOLITE™yielded a conductivity of 4112 md-ft and 224 Darcies permeability for apercent retained permeability of 50% compared to the control.

The results for conductivity and permeability of the Rain-X® coatedCARBOLITE® of Example 3 are reported in Table 8. TABLE 8 Hrs at Closure& Closure Temp Conductivity Permeability Temperature (psi) Deg F.(mD-ft) Width (in) (Darcies) −15 1000 150-200 Leakoff while heating andbreaking −1 1000 200 990 0.230 <dp = .0046 52 −0.7 1000 200 1979 0.230psi at 103 −0.5 2000 200 4538 0.227 0.5 ml/min 240 0 4000 200 3945 0.222213 5 4000 200 4835 0.221 263 10 4000 200 4736 0.220 258 20 4000 2004644 0.220 253 30 4000 200 4511 0.220 246 40 4000 200 4536 0.220 247 504000 200 4556 0.220 249

As reported in Table 8, after 50 hours regain, the Rain-X® coatedCARBOLITE® yielded a conductivity of 4556 mD-ft and 249 Darciespermeability for a percent retained permeability of 55% compared to thecontrol. Thus, the percent retained permeability of the Rain-X® coatedCARBOLITE® proppant of Example 3 was 5% greater than the uncoatedCARBOLITE® proppant.

Based on the foregoing results, it may be concluded that all coatedproppant samples showed improved conductivity and retained permeabilitywhen compared to uncoated proppant. In addition, the polymethylhydrogensiloxane and polydimethyl siloxane coated CARBOHSP proppant samples hadconductivities of 3850 and 4121mD-ft, 64% and 68% retained permeability,respectively which compared quite favorably to the Rain-X® coatedCARBOHSP sample which had a conductivity of 3902 mD-ft and 67% retainedpermeability.

EXAMPLE 5

Additional results of testing performed on coated and uncoated samplesof CARBOHSP™ proppant are shown in Table 9. TABLE 9 20/40 HSP 20/40 HSPwith Rain-X ® ASG 3.56 3.26 Bulk Density (g/cm³) 2.00 2.01 Crush @ 15kpsi (%) 3.80 3.66 Sizing 16 0.0 0.0 20 5.2 5.2 25 43.5 43.5 30 45.145.1 35 6.0 6.0 40 0.2 0.2 50 0.0 0.0 pan 0.0 0.0 Conductivity (d-ft) @closure stress (kspi) @ 2 lbs/sqft 2 8.9 9.1 4 7.9 8.2 6 7.1 7.5 8 6.46.7 10 5.6 5.8 12 4.8 5.0

The coating of the CARBOHSP® proppant with Rain-X® was performed asdescribed above with respect to Example 2. The additional resultsindicate that the coated proppant exhibited an improved crush value overuncoated proppant, which may be due to improved “lubrication” of thecoated proppant. The additional results also indicate that the coatedproppant had a lower density than the uncoated proppant, which may bedue to the trapping of air bubbles around the proppant by the coating.The conductivity of the coated proppant was also improved over that ofthe uncoated proppant.

EXAMPLE 6

Additional testing was conducted with “wet” proppant having freshlyapplied coatings of Rain-X®, silicone spray, WD-40®, Black Magic andother materials to test the feasibility of the “on-the-fly” coatingapplication. These tests were repeated with separate samples after thecoating had dried to simulate an application process where the materialis coated before delivery to the wellsite. Both techniques demonstratedpotential benefits in reducing gel damage and modifying surfacewettability.

The time for a known volume of water to pass through a proppant pack wasrecorded, both for control groups (untreated conventional proppant) andproppants treated with a variety of coatings. In some tests, proppantsremained wet with the coatings, and in some tests, the coatings werepre-applied and allowed to entirely dry before loading the testapparatus. The test apparatus used to benchmark the effectiveness ofvarious coatings and application techniques both for wettability and gelrelease included a cylindrical tube with a valve at one end. The tubewas first packed with 17 ml. of proppant. The proppant was eithertreated or untreated for the control group. A known volume of a rinsefluid, typically water in the amount of 67 ml., was then added to thetube. The valve was opened and the time elapsed to drain the knownvolume of water through the proppant in the tube was recorded todetermine apparent permeability. In some tests, the proppants were mixedwith various fracturing fluids to estimate the gel adhesion to thecoated and uncoated proppants.

Table 10 shows the results of initial testing with four differentcoatings applied immediately before mixing with fracture gel. TABLE 10Gel Cleanup times with freshly applied coatings before mixing with gelslurry Dry spray Trial Uncoated “Gunk” Number proppant Black Magic WD40Silicone Silicone 1 26.8 43.1 32.9 42 24.9 2 13.9 15.4 14.4 13.8 13 311.7 14.2 10.1 15.3 10.4 4 12.3 13.2 11.7 13.7 10 5 12.6 12.5 11.6 13.710.9 6 11.9 13.2 11 7 11.9 13.1 8 11.9 12.2 9 12.7 12.6 10 12.2 12.912.7

One product was a spray-applied silicone, which dried almost immediatelyupon application, while the other “soak applied” coatings werenoticeably moist. The spray-applied product appeared to immediatelyreduce the time for water to pass through the proppant pack, andprovided sustained benefit in all subsequent flushes with fresh water.Also, the relatively “wet” coatings significantly delayed theinfiltration of water into the pack, delaying cleanup, but potentiallyreducing “viscous fingering” which may be a significant benefit in someapplications.

Table 11 shows the results of further experimentation with “dry”applications of Rain-X®. TABLE 11 Gel Cleanup times with freshly appliedcoatings before mixing with gel slurry Trial Uncoated RainX ® RainX ®Uncoated Number proppant, no gel with gel no gel proppant with gel 111.1 23.3 10.6 35 2 11 9.8 12.7 15.5 3 10.8 10.3 13.6 15.2 4 11 10.415.8 15.3 5 11.2 11 14.1 16.4 6 11.2 16 16.9 7 11.9 15.2 16.1 8 12.3 1615.4 9 11.8 14.9 10 12.6 11 12.6 12 12.8 13 13.2 14 13.1 15 13.2 16 12.817 12.9 18 13.5

Two trends were noted from the results shown in Table 11. First, in bothgel-contaminated and uncontaminated packs, the Rain-X® treated proppantinitially allowed reduced flowtimes. Secondly, both samples treated withRain-X® showed significantly increasing flowtimes to water withsubsequent flushes. It was visually observed that the Rain-X® coatedproppant trapped air bubbles that accumulated over time. It was clearthat the proppant was hydrophobic. On several attempts, it was notedthat the applied column of water could not infiltrate the dry pack todisplace the air until after flow initiated. Further experimentationdemonstrated that the pack could support an 8 to 10 inch column of waterwithout any measurable infiltration by the water phase. In the presenceof a multiphase system such as a gas well, this proppant would beexpected to preferentially produce natural gas, while hindering the flowof water which would provide a tremendous economic benefit. The resultsshown in Table 11 clearly demonstrate the affinity of the coatedproppant to be gas or oil-wet rather than water-wet. Additionally, itwas noted that the Rain-X® precoated sample showed dramatically bettergel cleanup than the uncoated proppant sample. In addition, theintentional alteration of the wettability of a proppant willsignificantly change the fluid flow characteristics within the porestructure of the proppant. Since formation fines are typicallytransported only by the water phase (the fines are water-wet), suchcoated proppants may be significantly less damaged by migrating finesthan conventional non-treated proppants.

EXAMPLE 7

According to this Example, a multiphase flow test was conducted. Themultiphase flow test was conducted with respect to uncoated andpolydimethyl siloxane coated CARBOHSP® and a slurry of the proppant wastop loaded between two saturated Ohio Sandstone cores. In this Example,the proppant samples were evaluated at 4000 psi closure stress and 150°F. In this test, saturated gas was flowed through the cells at aconstant rate (26 l/min) while increasing rates of water weresimultaneously pumped through. The differential pressure was measured asthe liquid flow was increased; and it was desired that the differentialpressure or “dP” be as low as possible. The results from the multiphaseflow test are shown in Table 12. TABLE 12 Liquid Flow DifferentialPressure (bar) Rate Polydimethyl (g/min) Uncoated Siloxane 0 0.061 0.03946.1 0.143 0.120 63.7 0.233 0.176 99.0 0.401 0.296 152.3 0.479 0.437 00.079 0.055

As set forth in Table 12, the polydimethyl siloxane coating showedimproved (lower) pressure differential at all liquid flow rates comparedto the uncoated control. Also, the beta factor for the polydimethylsiloxane sample was improved: 0.205 atm·s²/kg compared to 0.262atm·s²/kg for the uncoated control. The multiphase flow test results interms of a lower beta and improved multiphase flow for the polydimethylsiloxane coated CARBOHSP™ compared to the control indicated that thepolydimethyl siloxane coating created a much smoother surface andcovered some of the surface porosity of the CARBOHSP™. It was confirmedby scanning electron microscopy (“SEM”) at a power of 500×that thepolydimethyl siloxane coating had indeed created a much smoother surfaceand appeared to have covered substantially all of the surface porosityof the CARBOHSP™.

The chemically coated and/or treated particles of the present inventionare useful as a propping agent in methods of fracturing subterraneanformations to increase the permeability thereof.

When used as a propping agent, the particles of the present inventionmay be handled in the same manner as other propping agents. Theparticles may be delivered to the well site in bags or in bulk formalong with the other materials used in fracturing treatment.Conventional equipment and techniques may be used to place the particlesas a propping agent.

A viscous fluid, frequently referred to as a “pad”, is injected into thewell at a rate and pressure to initiate and propagate a fracture in thesubterranean formation. The fracturing fluid may be an oil base, waterbase, acid, emulsion, foam, or any other fluid. Injection of thefracturing fluid is continued until a fracture of sufficient geometry isobtained to permit placement of the propping pellets. Thereafter,particles as hereinbefore described are placed in the fracture byinjecting into the fracture a fluid or “slurry” into which the particleshave previously been introduced and suspended. Following placement ofthe particles, the well is shut-in for a time sufficient to permit thepressure in the fracture to bleed off into the formation. This causesthe fracture to close and apply pressure on the propping particles whichresist further closure of the fracture. The resulting proppantdistribution is usually, but not necessarily, a multi-layer pack.

The foregoing description and embodiments are intended to illustrate theinvention without limiting it thereby. It will be understood thatvarious modifications can be made in the invention without departingfrom the spirit or scope thereof.

1. A gas and oil well proppant comprising: a plurality of essentiallyspherical particles, wherein the particles are coated with a hydrophobicmaterial.
 2. The proppant of claim 1, wherein the hydrophobic materialcomprises one or more hydrophobic materials selected from the groupconsisting of silicones, siloxanes, polytetrafluoroethylene, plant oils,hydrocarbons, copolymerized polyvinylidene chloride, glass frit andenamel.
 3. The proppant of claim 1, wherein the proppant particles arecoated with the hydrophobic material by one or more of spraying, dippingor soaking the proppant particles in a liquid solution of thehydrophobic material, applying a sheet of film to the proppantparticles, fusing material to the proppant particles, electroplating,plasma spraying, sputtering, fluidizing and powder coating.
 4. Theproppant of claim 2, wherein the hydrophobic material comprises asiloxane based on the structural unit R₂SiO, wherein R is an alkylgroup.
 5. The proppant of claim 2, wherein a hydrophobic materialcomprises a nonvolatile linear siloxane of the composition:

where (R₁) is an alkyl group having from one to three carbon atoms, (R₂)is hydrogen or an alkyl group having from one to three carbon atoms,(R₃) is an alkyl group having from one to four carbon atoms and n is anumber between 50 and
 200. 6. The proppant of claim 2, wherein thehydrophobic material is selected from the group consisting ofpolymethylhydrogen siloxane and polydimethyl siloxane.
 7. The proppantof claim 2, wherein the plant oils comprise at least one member selectedfrom the group consisting of linseed oil, soybean oil, corn oil,cottonseed oil, vegetable oil and canola oil.
 8. The proppant of claim2, wherein the hydrocarbons comprise at least one member selected fromthe group consisting of kerosene, diesel, crude oil, petroleumdistillates, aliphatic solvents, solvent naphtha and paraffin.
 9. Amethod of fracturing a subterranean formation, comprising: injecting ahydraulic fluid into a subterranean formation at a rate and pressuresufficient to open a fracture therein; and injecting into the fracture afluid containing a plurality of essentially spherical particles, whereinat least some of the particles are modified to alter the surfacecharacteristics thereof, wherein the particles are modified by coatingthe particles with a hydrophobic material.
 10. The method of claim 9,wherein the hydrophobic material comprises one or more hydrophobicmaterials selected from the group consisting of silicones, siloxanes,polytetrafluoroethylene, plant oils, hydrocarbons, copolymerizedpolyvinylidene chloride, glass frit and enamel.
 11. The method of claim9, wherein the proppant particles are coated with the hydrophobicmaterial by one or more of spraying, dipping or soaking the proppantparticles in a liquid solution of the hydrophobic material, applying asheet of film to the proppant particles, fusing material to the proppantparticles, electroplating, plasma spraying, sputtering, fluidizing andpowder coating.
 12. The method of claim 9, wherein the modification ofthe particles alters at least one of the chemical reactivity of theparticles, the surface topography of the particles, the wettability ofthe particles and the lubricity of the particles.
 13. The method ofclaim 10, wherein the particles are coated with a silicone prior toinjection into the fracture.
 14. The method of claim 10, wherein theparticles are coated with a silicone during injection into the fracture.15. The method of claim 10, wherein the hydrophobic material comprises asiloxane based on the structural unit R₂SiO, wherein R is an alkylgroup.
 16. The method of claim 10, wherein the hydrophobic materialcomprises a nonvolatile linear siloxane of the composition:

where (R₁) is an alkyl group having from one to three carbon atoms, (R₂)is hydrogen or an alkyl group having from one to three carbon atoms,(R₃) is an alkyl group having from one to four carbon atoms and n is anumber between 50 and
 200. 17. The method of claim 10, wherein thehydrophobic material is selected from the group consisting ofpolymethylhydrogen siloxane and polydimethyl siloxane.
 18. The method ofclaim 10, wherein the plant oils comprise at least one member selectedfrom the group consisting of linseed oil, soybean oil, corn oil,cottonseed oil, vegetable oil and canola oil.
 19. The method of claim10, wherein the hydrocarbons comprise at least one member selected fromthe group consisting of kerosene, diesel, crude oil, petroleumdistillates, aliphatic solvents, solvent naphtha and paraffin.
 20. Amethod of modifying the surface properties of hydraulic fracturingproppant particles, comprising: coating the particles with a hydrophobicmaterial.
 21. The method of claim 20, wherein the hydrophobic materialcomprises one or more hydrophobic materials selected from the groupconsisting of silicones, siloxanes, polytetrafluoroethylene, plant oils,hydrocarbons, copolymerized polyvinylidene chloride, glass frit andenamel.
 22. The method of claim 20, wherein the proppant particles arecoated with the hydrophobic material by one or more of spraying, dippingor soaking the proppant particles in a liquid solution of thehydrophobic material, applying a sheet of film to the proppantparticles, fusing material to the proppant particles, electroplating,plasma spraying, sputtering, fluidizing and powder coating.
 23. Themethod of claim 20, wherein the modification of the particles alters atleast one of the chemical reactivity of the particles, the surfacetopography of the particles, the wettability of the particles and thelubricity of the particles.
 24. The method of claim 20, wherein thehydrophobic material comprises a siloxane based on the structural unitR₂SiO, wherein R is an alkyl group.
 25. The method of claim 20, whereinthe hydrophobic material comprises a nonvolatile linear siloxane of thecomposition:

where (R₁) is an alkyl group having from one to three carbon atoms, (R₂)is hydrogen or an alkyl group having from one to three carbon atoms,(R₃) is an alkyl group having from one to four carbon atoms and n is anumber between 50 and
 200. 26. The method of claim 20, wherein thehydrophobic material is selected from the group consisting ofpolymethylhydrogen siloxane and polydimethyl siloxane.
 27. The method ofclaim 20, wherein the plant oils comprise at least one member selectedfrom the group consisting of linseed oil, soybean oil, corn oil,cottonseed oil, vegetable oil and canola oil.
 28. The method of claim20, wherein the hydrocarbons comprise at least one member selected fromthe group consisting of kerosene, diesel, crude oil, petroleumdistillates, aliphatic solvents, solvent naphtha and paraffin.